Results of a Tertiary Hot Waterflood in a Thin Sand Reservoir
- W.L. Martin (Continental Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1968
- Document Type
- Journal Paper
- 739 - 750
- 1968. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 5.8.5 Oil Sand, Oil Shale, Bitumen, 1.6.9 Coring, Fishing, 5.4.6 Thermal Methods, 6.5.2 Water use, produced water discharge and disposal, 1.14 Casing and Cementing, 2.4.3 Sand/Solids Control, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements, 1.6 Drilling Operations, 5.1.1 Exploration, Development, Structural Geology, 5.3.2 Multiphase Flow, 2.4.5 Gravel pack design & evaluation, 4.2.3 Materials and Corrosion, 5.6.5 Tracers, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 5.5.2 Core Analysis, 4.3.4 Scale, 5.3.4 Reduction of Residual Oil Saturation, 2.2.2 Perforating
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This paper presents and discusses the results obtained daring a pilot test in the Loco field in southern Oklahoma. The test was conducted in a 2 1/2-acre pattern that was part of a 20-acre conventional waterflood pilot area. The conventional flood was well past its economic limit when the hot waterflood was initiated to obtain technical information from and operating experience in a reservoir containing 600 cp oil.
Temperature data from nine observation wells showed that about 75 percent of the pattern was affected by heal, and that heat losses were severe in the pilot pattern. About 60 percent of the injected heat was lost to overburden and underburden zones during hot-water injection. Wellbore heat losses were held at tolerable levels at the shallow depth of the test by providing a low-pressure air annulus between the injection tubing and well casing.
Hot water provided water injectivity increases of 200 to 400 percent. The hot water channeled across the lower portion of the oil sand in three directions through zones of relatively high water saturation. There was no conclusive evidence that natural fractures or pressure partings affected the flow of fluids in the pilot pattern; however response undoubtedly was affected by localized pressure and by injection-production rate ratios.
The results snowed that hot waterflooding increased oil recovery. The total tertiary oil production from the pilot pattern area was 3,896 bbl or about 156 bbl/acre-ft swept by neat. The corresponding WOR was about 34:1.
Description of the Hot Waterflood Process
To hot waterflood an oil reservoir, water is injected that has been heated to a temperature substantially higher than the original reservoir temperature, but lower than the vaporization temperature of water at the prevailing pressures. In the reservoir the hot water flows continuously into cooler sand and rapidly loses heat to the sand until it has been cooled to the original reservoir temperature. Thus, a heated zone and a region or "bank" of cooled water begins to accumulate immediately after hot water injection is started. This bank of cooled water continues to grow ahead of the heated zone, which also grows, but at a slower rate. This occurs because heat transfer is almost instantaneous, and the ratio of heat capacities of water to rock is such that two or three unit PV of hot water must be injected to heat a given unit bulk volume of the reservoir. The primary displacement mechanism is the same for both hot and conventional cold waterfloods; i.e., "piston" displacement occurs at the original reservoir temperature. The incremental benefits of hot waterflooding usually occur long after the breakthrough of cold water at producing wells, and the increased oil recovery necessarily is accomplished with high WOR's (water-oil ratios).
Heat decreases the viscosity and density of oil and water. These effects result in more rapid and increased recovery of secondary or tertiary oil. If the cost of the required heat is low enough, the ultimate oil recovery of a hot waterflood should be increased substantially over what would be expected at the economic limit of a conventional cold waterflood.
The economic benefits of any hot-fluid injection project depend primarily upon the cost of the heat required to produce more oil at an increased rate. This cost depends in part upon the amount of heat lost to surrounding formations. Heat loss depends upon reservoir thickness, water injection rate and temperature, the depth of the formation. well spacing, and the characteristics of the reservoir rock and surrounding formations. In general, percentage heat losses decrease as injection rate and reservoir thickness increase.
Although it is an old idea, hot-water injection has not received widespread field application in the oil industry as a drive process. Much of the original field work with hot water was done in Pennsylvania fields where water permeabilities and injection rates are low. In these cases, hot-water injection was used primarily as a means of increasing injectivities - not as a recovery process. Ramey recently has published an excellent review of the development of hot fluid injection processes.
Recent publications and our own experiences now indicate that hot water or steam injection also can effectively increase the oil recovery from reservoirs containing viscous crudes. However, the economics of these methods as displacement processes have not been established.
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